ML16222A875
| ML16222A875 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 10/20/1994 |
| From: | Harmon P, Sinkule M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML16154A693 | List: |
| References | |
| 50-269-94-28, 50-270-94-28, 50-287-94-28, NUDOCS 9411070192 | |
| Download: ML16222A875 (14) | |
See also: IR 05000269/1994028
Text
V REGo
UNITED STATES
&
NUCLEAR REGULATORY COMMISSION
REGION II
0
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
Report Nos.:
50-269/94-28, 50-270/94-28 and 50-287/94-28
Licensee:
Duke Power Company
422 South Church Street
Charlotte, NC 28242-0001
Docket Nos.:
50-269, 50-270, and 50-287
License Nos.:
Facility Name: Oconee Units 1, 2, and 3
Inspection Conducted:
August 28 - September 24, 1994
Inspectors:
7
P. E. Hargoini Senior Re d n)VInspector
Date Signed
W. K. Poertner, Resident Inspector
L. A. Keller, Resident Inspector
P. G. Humphrey, Resident Inspector
L. A. Wiens, Project Manager, NRR
Approved by:
'A-V d VJh-
10
A
M. V. Sinkule, Chief,
Date Si ned
Reactor Projects Branch 3
SUMMARY
Scope:
This routine, resident inspection was conducted in the areas of
plant operations, surveillance testing, maintenance activities,
and engineering. As part of this effort, backshift inspections
were conducted.
Results:
During this inspection period, three violations were identified.
The first violation involves the failure to follow procedure
during a modification activity which resulted in the loss of the
Unit 1 pressurizer spray valve and the majority of the Unit 1
radiation monitors, paragraph 3.c. The second violation involves
the lack of procedural guidance for the Babcock & Wilcox
compressive limit for Once Through Steam Generators, paragraph
6.b. The third violation involves the lack of adequate corrective
action for the problem of turbine bypass valves (TBVs) randomly
repositioning following the restoration of power to the TBV
control circuitry, paragraph 6.c.
An inspection of the licensee's 10 CFR 50.59 program (changes,
tests and experiments) revealed that although an incorrect
interpretation of 10 CFR 50.59 reporting requirements had been
9411070192 941020
ENCLOSURE 2
ADOCK 05000269
2
made, the licensee had adequately implemented the requirements of
10 CFR 50.59, paragraph 4.
REPORT DETAILS
1.
Persons Contacted
Licensee Employees
- B. Peele, Station Manager
E. Burchfield, Regulatory Compliance Manager
0. Coyle, Systems Engineering Manager
J. Davis, Engineering Manager
T. Coutu, Operations Support Manager
B. Dolan, Safety Assurance Manager
W. Foster, Superintendent, Mechanical Maintenance
J. Hampton, Vice President, Oconee Site
D. Hubbard, Superintendent, Instrument and Electrical (I&E)
C. Little, Electrical Systems/Equipment Manager
G. Rothenberger, Operations Superintendent
R. Sweigart, Work Control Superintendent
Other licensee employees contacted included technicians, operators,
mechanics, security force members, and staff engineers.
- Attended exit interview.
O2.
Plant Operations (71707)
a.
General
The inspectors reviewed plant operations throughout the reporting
period to verify conformance with regulatory requirements,
Technical Specifications (TS), and administrative controls.
Control room logs, shift turnover records, temporary modification
log and equipment removal and restoration records were reviewed
routinely. Discussions were conducted with plant operations,
maintenance, chemistry, health physics, instrument & electrical
(I&E), and engineering personnel.
Activities within the control rooms were monitored on an almost
daily basis.
Inspections were conducted on day and night shifts,
during weekdays and on weekends.
Inspectors attended some shift
changes to evaluate shift turnover performance. Actions observed
were conducted as required by the licensee's Administrative
Procedures. The complement of licensed personnel on each shift
inspected met or exceeded the requirements of TS. Operators were
responsive to plant annunciator alarms and were cognizant of plant
conditions.
Plant tours were taken throughout the reporting period on a
routine basis.
During the plant tours, ongoing activities,
housekeeping, security, equipment status, and radiation control
practices were observed.
- I
2
b.
Plant Status
All three Oconee Units operated at or near 100 percent power
throughout the inspection period.
Within the areas reviewed, licensee activities were satisfactory and no
violations or deviations were identified.
3.
Maintenance and Surveillance Testing (62703 and 61726)
a.
Maintenance activities were observed and/or reviewed during the
reporting period to verify that work was performed by qualified
personnel and that approved procedures adequately described work
that was not within the skill of the craft. Activities,
procedures and work orders (WO) were examined to verify that
proper authorization and clearance to begin work was given,
cleanliness was maintained, exposure was controlled, equipment was
properly returned to service, and limiting conditions for
operation were met. Maintenance activities observed or reviewed
in whole or in part are as follows:
(1) Perform Reactor Protection System (RPS) Channel B On-Line
Test (Work Order 94067026)
An in progress review of the Unit 2 Reactor Protection
System (RPS) channel B calibration was performed by the
inspector on September 12, 1994. The activity was
authorized per WO 94067026 which implemented Procedures
IP/O/A/305/3B, Nuclear Instrumentation RPS Removal From And
Return To Service For Channels A,B,C, and D, and
IP/2/A/305/3B, Nuclear Instrumentation And Reactor
Protective System Channel Calibration And Functional Test.
Technical Specification 4.1-1 required the test to be
accomplished once per 180 days.
The inspector determined that the activity was performed and
documented in accordance with the applicable procedures.
As-found and as-left data was verified by the inspector to
be within the tolerances allowed by the procedures and the
work effort was considered acceptable.
(2) Replace Valve 3AS-256 Work Order (94067915)
Maintenance work activities were reviewed by the inspector
during the replacement of Auxiliary Steam Valve 3AS-256 on
September 14, 1994. An Auxiliary Steam System outage was
initiated on September 10, for the repair and replacement of
various valves in the system which had been identified as
having leaks and other problems. The work reviewed
consisted of replacing a 1-inch gate with a 1-inch globe
valve because of seat leaks and the unavailability of parts
to repair the gate valve.
Both manual replacement valves
3
were carbon steel, had socket type fittings, and were
required to be welded into place.
The inspector determined the activity and related
documentation had been acceptably performed.
(3) Perform NSM 12881 Part D, Replace Power Chargers (Work Order 94009533)
Maintenance work activities were witnessed and reviewed by
the inspectors during the replacement of the 1PB battery
charger on September 22, 1994. The work reviewed consisted
of disconnecting the old 1PB battery charger to allow
removal of the charger from the turbine building. The
maintenance reviewed was accomplished in accordance with
approved procedures and no discrepancies were noted.
(4) Troubleshoot Erratic LPSW Flow Indication For LPI Cooler 3A
During the last refueling outage on Unit 3, the indicated
flow of low pressure service water (LPSW) through the 3A Low
Pressure Injection (LPI) cooler was erratic at low flow
rates. The inspector observed the troubleshooting efforts
conducted on the applicable instrument string (3LPSFT0124)
conducted September 22, 1994. The as-found string check
revealed that the output of the instrument string was
slightly out-of-tolerance low. The applicable Rosemount
transmitter was adjusted up slightly which brought the
entire instrument string in tolerance. All activities
observed were satisfactory.
b.
The inspectors observed surveillance activities to ensure they
were conducted with approved procedures and in accordance with
site directives. The inspectors reviewed surveillance
performance, as well as system alignments and restorations. The
inspectors assessed the licensee's disposition of any
discrepancies which were identified during the surveillance.
Surveillance activities observed or reviewed in whole or in part:
(1) Low Pressure Injection Pump Test-Recirculation
(PT/1/A/0203/06A)
The inspector witnessed performance testing of the 1B Low
Pressure Injection (LPI) pump on September, 1, 1994. The
pump was operated in recirculation from the Borated Water
Storage Tank (BWST) and various operating parameters were
monitored to determine operability based on established
acceptance criteria. These parameters included the ability
to meet flow and pressure requirements specified for that
unit. In addition, vibration data was taken and compared
4
with the acceptance criteria, and check valves on the
adjacent pumps were evaluated to verify proper closure and
seating.
The inspector verified that the test was performed in
accordance with the procedure, test instruments utilized for
obtaining the data were within current calibration, and test
results were properly documented. All testing activities
were determined to be satisfactory.
(2) Keowee Turbine Guide Bearing Oil Cooler Test (TT/O/A/610/12)
This temporary test procedure was performed to determine the
lake temperature at which the Keowee turbine guide bearing
oil cooler is required to be operable for the Keowee units
to provide emergency power to the Oconee main feeder buses.
The procedure operated a Keowee hydro unit at approximately
69 MWe for approximately 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> then reduced load to 20 'MWe
to simulate emergency load conditions with an isolated oil
cooler. The unit was then operated for approximately 6
hours at 20 MWe and turbine bearing temperature and bearing
oil temperature were recorded.
The inspector reviewed the test procedure and the test data
obtained. The inspectors noted that bearing temperature did
not stabilize during the performance of the test procedure.
Bearing temperature increased 1.7 degrees centigrade during
the first hour that the cooler was isolated and increased
0.65 degrees centigrade during the sixth hour when the test
was finally secured. Discussions with the licensee
determined that further evaluation would be required to
determine if the turbine guide bearing oil cooler could be
isolated at certain lake temperatures.
(3) High Pressure Injection Pump Test (PT/1/A/0202/11)
The inspectors monitored the performance of this
surveillance procedure conducted on September 22, 1994. The
procedure established 90 gpm combined makeup and seal
injection flow and verified pump performance in accordance
with the requirements of ASME Section XI.
During performance of the procedure, letdown temperature
increased above the high temperature alarm setpoint (120
degrees F) when makeup flow was increased to achieve 90 gpm
total flow. Makeup flow was reduced to return letdown
temperature to within normal limits. The 1A letdown cooler
had been isolated previously in the cycle due to leakage 'and
the operators were reluctant to place the second letdown
cooler in service to continue with the procedure. The test
III5
was aborted until an evaluation could be performed to
determine the appropriate course of action to accomplish the
procedure.
The inspectors monitored operator performance in the control
room during performance of the procedure. The operators
were cognizant of plant conditions and conducted the
procedure in a methodical manner. The inspectors will
review this item further during the next inspection period.
(4) Low Pressure Service Water Valve Stroke Test
(PT/1/A/0150/22T)
On September 23, 2994, the inspector witnessed stroke time
testing of the Unit 1 Low Pressure Service Water (LPSW)
Valves associated with the 1A and IB LPI Coolers. The
testing was required to be performed quarterly to satisfy
Technical Specifications, Section 3.3 and 4.0.4. The
equipment performed within the operating parameters
specified in the procedure. The test and conduct of the
testing was determined acceptable.
(5) 2B Reactor Building Spray Pump Test (PT/2/A/0204/07)
On September 8, 1994, the inspector witnessed an operability
test of the 2B Reactor Building Spray Pump. All pump
parameters measured were within the acceptance criteria and
all activities observed were satisfactory.
(6) Stroke Test of 3FDW-315 (PT/3/A/0150/22M)
The inspector observed the stroke test of the 2A Steam
Generator Emergency Feedwater Control Valve on September 14,
1994. The stroke time was within acceptance criteria and
consistent with previous stroke times. All activities
observed were satisfactory.
(7) Pressure Instrument Calibration for the Unit 3 PALSS System
(IP/0/B/0210/012)
On September 19, 1994, the inspector witnessed the
calibration of pressure measuring instruments in the Post
Accident Liquid Sampling System (PALSS) for Unit 3. The
inspector verified the work was being performed under an
approved radiation work permit (RWP) and that the dress
requirements for this RWP were being met. All activities
observed were satisfactory.
c.
Loss of Motor Control Center IXO
At approximately 11:04 a.m., on September 12, 1994, the supply
breaker to motor control center (MCC) 1XO tripped. The loss of
- II6
MCC 1XO resulted in the loss of power to the majority of the Unit
1 radiation monitors and the pressurizer spray control valve along
with numerous lighting panels and nonsafety-related valves.
Investigation by the licensee determined that the MCC tripped due
to a phase to phase short that resulted from an inadequately
implemented modification package. Modification procedure
TN/1/A/2881/0/DL1, Unit 1 power Battery Charger 1PA, 1PB, and IPS
Replacement, replaced breaker IF1AT on MCC 1XO with a 150 amp
breaker. Step 8.8.10 of TN/1/A/2881/0/DL1 required that the
internal wiring of the replacement breaker assembly be verified by
performing a meg ohm (continuity) check between the conductors.
The maintenance personnel performing the work activity had rolled
the leads on the breaker and had not performed the required meg
ohm check prior to attempting to install the replacement breaker
into the breaker cubicle. MCC 1XO was energized during the
modification process. The failure to meet the procedural
requirements of procedure TN/1/A/2881/0/DL1 is identified as
Violation 269/94-28-01:
Failure to Follow Procedure.
The improperly wired breaker was removed and the MCC was inspected
for damage. The inspection revealed minor arc and splatter damage
to the bus and insulators. The MCC was reenergized at
approximately 2:16 p.m.
The inspectors monitored licensee actions to restore power to the
MCC, inspected the damage to the MCC and verified that the
compensatory actions required by selected licensee commitment
16.11, Radiological Effluents Control, with respect to the loss of
the radiation monitoring instruments were implemented in a timely
manner. Subsequent to restoring power to the MCC the inspectors
reviewed the modification procedure.
Within the areas reviewed one violation, involving failure to follow
procedure, was identified. All other activities observed were
satisfactory.
4.
Onsite Engineering (37551 and 37001)
During the inspection period, the inspectors assessed the effectiveness
of the onsite design and engineering processes by reviewing engineering
evaluations, operability determinations, modification packages and other
areas involving the Engineering Department. Additionally, an evaluation
of the implementation of the requirements of 10 CFR 50.59 was performed
by the NRR Project Manager with assistance from the Oconee Resident
Inspectors on September 21 and 22, 1994.
10 CFR 50.59 Safety Evaluation Program
The inspection addressed three principal areas: (1) Procedures and
Controls; (2)
Training and Qualification; and (3) Implementation, which
involves the performance of screenings and Unreviewed Safety Question
- II7
(USQ) evaluations. The inspectors reviewed Nuclear System Directives
(NSD), Oconee Site Directives (OSD), Training Records, and individual
screening and USQ packages for modifications and procedure changes. As
part of the inspection, a review of a 10 CFR 50.59 Implementation Review
conducted by the licensee's Safety Review Group between June 15, and
July 21, 1994, was performed.
The procedural guidance had been recently revised, but the licensee
indicated that the process for performing the safety evaluations had not
changed in a significant fashion. The specific procedures reviewed were
NSD 209, "10CFR 50.59 Evaluations", NSD 213, "Conduct of Infrequently
Performed Tests or Evolutions", NSD 301, "Nuclear Station
Modifications", OSD 2.1.4, "Control of Temporary Modifications", and OSD
2.2.1, "Control of Minor Modifications". The inspectors determined that
the guidance adequately addressed the 10 CFR 50.59 criteria. No
deficiencies were identified.
A sampling of the 50.59 screening for USQ applicability was performed.
The inspectors reviewed both screenings which determined that a USQ
evaluation was not required and screenings for which a USQ evaluation
was necessary. For the screening evaluations reviewed, the USQ
determinations made by the licensee were appropriate. Reviews of safety
evaluations performed in support of USQ determinations were generally
well written, sufficiently detailed and adequately addressed the 50.59
criteria.
The annual report submitted in accordance with 10 CFR 50.59(b)(2) for
the period January 1, 1993, to December 31, 1993, did not include all of
the changes, tests and experiments (CTEs) performed under this
provision. An interpretation had been made that only those changes that
required a change to the Final Safety Analysis Report (FSAR) needed to
be reported. However, the regulations did not limit the report in this
fashion. The licensee committed that future reports will include all
CTEs performed under the criteria of 10 CFR 50.59.
The 10 CFR 50.59 Implementation Review conducted by the Oconee Safety
Review Group between June 15, and July 21, 1994 (Report No. IP94-08),
was reviewed as part of the inspection. The report appeared to be a
thorough, detailed, candid evaluation. In addition to specific findings
on errors in some packages, a general weakness was found in the area of
training. No formal training was required for 50.59 preparers, and no
requalification training in 50.59 requirements and criteria was required
for anyone involved in these reviews.
Initial training in 50.59
criteria and requirements was required for Qualified Reviewers prior to
performing 50.59 reviews and approvals. Since preparers and Qualified
Reviewers are diversified throughout the Oconee organization,
particularly for minor modifications and procedure changes, the
inspectors agreed that this was a weakness in the program. Although the
licensee had taken measures to strengthen the initial training for
Qualified Reviewers, no decision had been made on providing specific
50.59 training for preparers or requalification training for personnel
involved in the 50.59 review and approval process.
- II8
Overall, the inspectors concluded that the licensee had adequately
implemented the requirements of 10 CFR 50.59'.
Safety issues pertinent
to associated changes, tests and experiments were adequately resolved.
There were no significant deficiencies or violations of NRC requirements
identified, although an incorrect interpretation of 10 CFR 50.59
reporting requirements had been made.
No violations or deviations were identified.
5.
Plant Support (71750)
The inspectors assessed selected activities of licensee programs to
ensure conformance with facility policies and regulatory requirements.
During the inspection period, the following areas were reviewed:
radiological controls; radiological effluent, waste treatment, and
environmental monitoring; physical security; and fire protection.
The inspectors observed that the plant and surrounding areas were kept
clean and free of materials that could increase fire loading in those
areas. Although scaffolding has been erected in preparation of the Unit
2 Refueling Outage, scheduled to begin on October 6, 1994, the materials
involved have been treated for fire resistance.
Within the areas reviewed, all activities observed were satisfactory.
6.
Inspection of Open Items (92902 and 92903)
The following open items were reviewed using licensee reports,
inspection record review, and discussions with licensee personnel, as
appropriate:
i
a.
(Closed) Unresolved Item 269,270,287/94-24-03: Past Operability of
the Keowee Overhead Emergency Power Path During Maintenance
Activities on the Associated Underground Feeder Breaker
This item identified a potential violation of technical
specification requirements associated with the Keowee overhead
emergency power path during breaker maintenance activities on the
associated underground feeder breaker. Technical Specification 3.7.2 requires that the alternate emergency power path be verified
operable within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and every eight hours thereafter if one of
the two emergency power paths becomes inoperable. The licensee
performed an operability evaluation and determined that the
overhead emergency power path had never been inoperable for
greater than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> as a result of the maintenance activities on
the underground feeder breakers. The inspectors discussed this
item with cognizant licensee personnel and reviewed the licensee
operability evaluation. No discrepancies were noted.
b.
(Closed) Unresolved Item 269,270,287/94-24-01: Compressive Limit
for Steam Generator Differential Temperature Exceeded
9
On August 10, 1994, following a loss of the "KI" inverter, there
was a reactor trip and a random repositioning of the turbine
bypass valves which ultimately resulted in a dryout of the 3B Once
Through Steam Generator (OTSG). When the licensee began
preparations to recover the 3B OTSG, they became aware of the B&W
limit for differential temperature between the tubes and shell (60
degrees fahrenheit - tubes hotter than shell). This limit was
established by the vendor to minimize compressive stresses on the
OTSG tubes. The licensee had not incorporated this generic
guidance into their procedures/training. Consequently, the
operators and licensee management were initially unaware of this
limit and eventually exceeded the limit by 22 degrees fahrenheit.
While discussing the particulars on how to re-establish feedwater
to the 3B SG, a licensee employee recalled that there was a limit
for tube/shell differential temperature. The inspectors
determined that absent this recollection (which was not part of
any formal training) there was no formal mechanism
(alarms/procedural guidance) to alert the operators to this limit.
Therefore, it was somewhat fortuitous that the limit was not
exceeded by more than 22 degrees.
The licensee subsequently stated in the associated Licensee Event
Report (LER 287/94-02) that "The decision to exclude this limit
from the Emergency Operating Procedure (EOP) was a conscious
decision by the procedure writers and reviewers. This decision
was based on the fact that no scenario was foreseen that would
challenge the limit, provided that the guidance in the EOP was
followed in a timely manner. An extended delay in restoring
feedwater to a dry steam generator (SG) was not anticipated during
the development of the EOP. Therefore, it was considered
unnecessary to document the limit in the EOP."
The inspectors
concluded that the decision to exclude this limit from the EOP was
inappropriate, based on the fact that there are scenarios where a
steam generator could depressurize or dry out and the amount of
time necessary to recover the steam generator could be extended.
Therefore, the maximum SG tube/shell differential temperature
limit should have been procedurally addressed. This item is
identified as Violation 269,270,287/94-28-02: Compressive Limit
for Steam Generator Differential Temperature Not Addressed in
Procedures.
c.
(Closed) Unresolved Item 269,270,287/94-24-02:
Corrective Actions
Associated With Turbine Bypass Valves Randomly Repositioning
On August 10, 1994, following a temporary loss of power to the
Unit 3 Integrated Control System (ICS), the turbine bypass valves
(TBV) randomly repositioned following restoration of power. This
resulted in the dryout of the 3B OTSG. The fact that the TBVs
randomly reposition after power restoration was known by the
licensee since at least 1986. Following the Rancho Seco event of
December 1985, the licensee evaluated the effects of a restoration
of ICS/non-nuclear instrumentation power per the B&W Owners Group
recommendation TR-032-ICS. As part of this evaluation, the
licensee recognized that following a loss of power to the TBVs,
the TBVs would randomly reposition when power was restored. This
was due to the Static Analog Memory (SAM) modules, internal to the
TBV control circuitry, producing a random output voltage upon
power restoration. This output voltage is translated into TBV
position demand (0-100%). The licensee subsequently evaluated the
feasibility of replacing or modifying the SAM modules in order to
eliminate the random repositioning. However, due to monetary
controls and high backlog of proposed modifications at the time,
the licensee did not feel that modifying the TBVs was cost
effective.
On April 29, 1993, a momentary loss of Unit 2 KI power was
experienced. During the unit recovery, the control room operators
observed that the TBVs were in manual and partially open, which
resulted in some minor overcooling of the RCS. In the associated
Licensee Event Report (LER 270/93-01), the licensee stated that
the overcooling could have placed the unit in a less than adequate
shutdown margin position if the operators had not taken prompt
action to close the TBVs. In the Corrective Actions section of
the LER, the licensee committed to evaluate the Integrated Control
System to enhance the Turbine Bypass Valve control circuitry.
This evaluation was completed on November 15, 1993. The
evaluation concluded that new SAM modules that were not subject to
random output voltages on restoration of power should be
installed. The modification to install the new SAM modules was
prepared on June 30, 1994. Following the August 10, 1994 event,
the licensee installed these new modules on all three units.
Work was completed on August 13, 1994.
The inspectors questioned whether the licensee had ever
incorporated any procedural guidance to specifically check the
status of the TBVs immediately following a reactor trip. The
licensee responded that the only procedural guidance was the Loss
of KI Abnormal Procedure. The inspectors noted that by the time
the operators would reference the guidance in this procedure, one
or both steam generators could be blown dry. The lack of adequate
procedural guidance, or other corrective actions, from June 1986
until August 13, 1994, is identified as Violation 269,270,287/94
28-03: Corrective Actions Associated With Turbine Bypass Valves
Randomly Repositioning.
Within the areas reviewed, two violations were identified. One
violation involved inadequate procedural guidance for the compressive
limit for OTSGs (paragraph 6.b). The other violation involved
inadequate corrective action for TBVs randomly repositioning (paragraph
6.c).
7.
Review of Licensee Event Reports (92700)
The below listed Licensee Event Report (LER) was reviewed to determine
if the information provided met NRC requirements. The determination
included:
adequacy of description, compliance with Technical
Specification and regulatory requirements, corrective actions taken,
existence of potential generic problems, reporting requirements
satisfied, and the relative safety significance of each event. The
following LER is closed:
a.
(Closed) LER 287/93-02, Reactor Building Emergency Hatch Outer
Door Failed Open While the Inner Door Seal Was Inoperable
Resulting in a Technical Specification Violation
On April 4, 1993, Maintenance personnel entered the Unit 3 Reactor
Building Emergency Hatch (RBEH) for leak testing and noted an air
noise coming from around a portion of the sealing area for the
inner door. The inner door seal was declared inoperable. On
April 5, 1993, in preparation for inspecting the inner door seal,
the outer door was opened but was not re-closed within the time
allowed by Technical Specifications (10 minutes), due to
mechanical failure of the operating mechanism. The inner door
seal problem was due to mis-alignment of the door and sealing
surface. The hinge mechanism was not aligning the door to the
hatch properly due to inadequate maintenance on the hinge. The
problem with the outer door was slipping in the mechanical gear
train for the locking mechanism, causing the latch arm to extend
before the door shut.
Corrective actions included revising the preventive maintenance
(RM) procedure (MP/O/A/1400/05) for the RBEH to include
lubricating the inner and outer door hinges. Additionally, the
hinge pins on both doors were replaced as well as the miter gears,
gear shaft, and locking collars in the outer door locking
mechanism. The inspector reviewed the revised edition of the PM
procedure and found it to be acceptable. The inspector noted that
since repairs were made to the doors, they have functioned
properly.
For the LER reviewed, the licensee's corrective actions were
satisfactory.
8.
Exit Interview
The inspection scope and findings were summarized on September 29, 1994,
with those persons indicated in paragraph 1 above. The inspectors
described the areas inspected and discussed in detail the inspection
findings addressed in the summary and listed below. The licensee did
not identify as proprietary any of the material provided to or reviewed
by the inspectors during this inspection.
12
Item Number
Description/Reference Paragraph
50-269/94-28-01
VIOLATION:
Failure to Follow Procedure
(paragraph 3.c).
50-269,270,287/94-28-02
VIOLATION: Compressive Limit for Steam
Generator Differential Temperature Not
Addressed in Procedures (paragraph 6.b).
50-269,270,287/94-28-03
VIOLATION: Corrective Actions Associated
With Turbine Bypass Valves Randomly
Repositioning (paragraph 6.c).